SPE Introduction. Objectives. There are three primary objectives of this new pumping method:

Transcription

1 SPE Using a New Artificial-Lift System in Mexican Mature Oil Fields Vann Roy R./Vann Pumping, Gachuz-Muro Heron/Pemex E&P, Alcazar-Cancino Luis O./Pemex E&P, Guerra-López Mauricio/LLEGAR EOR International Copyright 2007, Society of Petroleum Engineers This paper was prepared for presentation at the 2007 SPE Annual Technical Conference and Exhibition held in Anaheim, California, U.S.A., November This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box , Richardson, Texas U.S.A., fax Abstract Throughout Mexico there are many oil wells in danger of being plugged or abandoned. These mature wells could possibly be made economical again by employing a new oil well pumping system using cable instead of rods. This pumping method is designed as an alternative to conventional rod and pump jack methods utilized in oil wells. Instead of rods to convey the up and down stroke of the downhole pump, cable is used. In place of pump jacks, an electronic and hydraulic operated system is employed with no visible moving parts on surface equipment. The pumping method unconventional offers many options and advantages that conventional pumping does not offer. The system is designed to operate safely and environmentally pleasing with low noise operation capability and a clean wellsite appearance with no oil leakage. In addition, an economic value is recognized when maintenance is required. A special cable unit is brought out to reel up and repair the downhole pumping assembly and return it to bottom; no workover unit is needed. This method has been developed and tested in Tyler, Texas for approximately seven years. Recent results in Mexico have shown many advantages. This paper presents various aspects (evaluation, development, working principle, etc) of this system and the field test results in Mexican Mature Oil Fields. The versatility of its characteristics has allowed us to maintain oil rates and reduce operational costs. This system discusses its difference with conventional methods and impact on production behavior. Introduction Objectives There are three primary objectives of this new pumping method: Reduce lifting cost per barrel Reduce maintenance and workover cost Enhance production The new system is designed as an alternative to conventional rod and pump jack methods utilized in oil well production today. Instead of rods to convey the up and down stroke of the downhole pump, cable is used. Not only is the pumping method (using cable) unconventional, it offers many options and advantages that conventional pumping does not offer. Increasing run time (reducing failure frequency) will increase a well's profit margin and recover more oil reserves (by lowering the economic limit). A major operating cost associated with sucker-rod pumping is the pulling and repair of the rods, pump, and tubing, as well as the replacement or repair of the surface pumping unit. Frequent repairs may make wells marginally economic. Repairs also decrease production because of well downtime. Using cable instead of rods to convey the up and down movement has been patented and it offers many advantages such as: Reduce overweight in the pumping system Less in cost per feet of cable compared with cost per feet of rods Reduce labor, maintenance, surveillance and operating costs Tension and Compression forces in the rods may cause damage to the rods and to the tubing. With the new system the cable is always in tension, which increases the pumping efficiency.

2 Testing Phase Initial testing of the well is necessary to perform a Check for Economics and to establish an optimum pumping rate as well as percent oil and water production. This testing phase is designed for mature oil fields and wells where most of the primary oil has been depleted and the well is classified as a "stripper well." Most of these wells have a water drive and the oil moves with the water. This testing phase will utilize a special testing wireline unit that will pump at various speeds to establish the optimum fluid level in the annulus. This will formulate the correct pump speed and rate to maintain a fluid level in the annulus at a point just above the level of the pump. By using this procedure it will be possible to pump twenty-four hours a day without the use of clocks for shutdown times. Procedures Take sample every 30 minutes and measure percentage oil cut. Fluid level in annulus is measured by surface sonar readout. Once optimum annulus fluid level is established, the computerized lifting system is set to maintain the desired annulus fluid level. Upon completion of the test phase, the tower unit is installed and its computerized system controls the pumping rate. Tower Pumping Unit After the short testing phase and optimum pumping rate has been determined, the cable is connected to a computerized hydraulic lifting system Figure 1. The size of the unit and the length of stroke will vary with the depth of the well and downhole well conditions. Advantages Total lifting cost reduction. The system is designed to reduce well testing, servicing, electricity, maintenance and manual surveillance costs. No workover unit needed to run or retrieve downhole pumps, which will lower maintenance cost. The system can be pulled by a special cable truck for any repairs needed. Longer stroke compared by many conventional pumping methods. Strokes per minute can be regulated to match production coming into well. No visible moving parts on surface equipment. The equipment is designed to operate safely. Environmentally pleasing with a much smaller footprint and a clean wellsite. Capability to notice chemicals between pump barrel and tubing. Chemicals are needed in this dead oil area and can be easily placed using this pumping method. These and many other unforeseen advantages have demonstrated the capability of changing an unprofitable well into a profitable well, often at no additional cost. Marginal oil wells are usually uneconomical for the major oil companies to operate because the labor and pumping costs are close to the revenue from the hydrocarbon sales. Every day many of these unprofitable wells are being plugged and abandoned. Many of these wells in Mexico produce only about 15 barrels or less of hydrocarbons/day. This system operates the well in such a manner that the production rate can be increased from marginal to profitable. Most oil wells are produced by a pump-jack unit that reciprocates a bottom-hole pump. The pump-jack usually operates cyclically for time intervals selected to avoid reaching a pump-off condition which starts a destructive condition known as fluid pounding, or gas lock. The method is operated in a continually pumped-off condition by removing the formation fluid from the bottom of the well just as fast as it enters through the casing perforations of the borehole, thereby reducing the hydrostatic pressure against the pay zone to a minimum. The low pumping speed of this cyclic operation along with the low bottom-hole pressure at the perforations prevents accumulation of gases within the pump barrel for more than one cycle of operation, and this is a situation in which fluid pounding cannot be brought about. The downhole production pump apparatus can be pulled from the tubing by using the operating cable for reeling the lifting cable uphole until the pump apparatus surfaces. Then the entire pump apparatus can be serviced, as required, with change out of desired parts, and thereafter run back downhole into the borehole by unspooling the cable. This system includes weight indicators, downhole sensing devices, including fluid level detecting devices, bottom hole pressure measurement, detection of oil/water contact or interface, and a cable actuated downhole production pump that can handle both oil and gas. All of these system parts are assembled and programmed to operate the downhole production pump at a production rate equal to the flow rate of the produced oil flowing into the well bore from the casing perforations. This keeps the hydrostatic head at the perforations at a minimum value which can be substantially zero, so that the downhole hydrostatic pressure imposed on the production zone is relatively low, which is a condition that achieves maximum production of oil from an oil well. Sensing devices are employed to control the action of the production apparatus which enable the speed of the operation to be controlled to match the rate of fluid input into the well bore at the casing perforations, thereby saving energy by allowing the pump to operate in a timed cyclic mode which upstrokes after there is a predetermined accumulation of production fluid in the pump barrel ready to be removed from the bottom of the borehole, Figure 2.

3 Accordingly, each time the operating cable is lowered into the borehole, diagnosis by the surface equipment determines the downhole fluid level, and, when there is less than a full pump barrel of formation fluid available to be transferred into the pump barrel, the timing of the next operating cycle is modified to coincide with the formation production rate so that a full pump barrel is attained prior to each stroke. This additional cycle time provides sufficient time for the well to make the additional fluid needed to completely fill the pump barrel with the accumulated well fluid and further keeps a minimum hydrostatic head at the perforations. In Mexico many of the unprofitable wells can be operated profitable by judiciously diagnosing the operating history of the well and carrying out any future operation of the well in accordance with this new pumping system. Applications The tower pumping unit may be used on any well that uses a downhole reciprocating pump to move fluid from the formation to the surface. As a consequence of the increase in exploration and drilling costs on developing new reserves, we should focus our efforts on improving and developing new techniques of oil recovery to extend the productive life of wells. In Mexico there is a wide opportunity for improved oil recovery technologies (IOR), there are many reservoirs that cannot be profitable with existing technologies. The system is a new pumping method that helps to efficiently increase the oil production while at the same time decreasing the cost of production. This system could lead to the recovery of significant amounts of remaining reservoirs in oil fields with low reservoir pressures in Mexico. In Mexico, the system has been installed in wells to depths of about 2150 meters (7,000 ft), results showed an oil production increase from 25 % to 75 %. It also reduces the oil/water ratio from 85 % to 65% by skimming the oil from above the oil/water interface of the formation fluid accumulated in the bottom of the well. When using the new system the power consumption was reduced in 50% compared with the pumpjacks. Curently, fifty wells are being analysed for workover with this type of system. Reservoir Description The mature oil field is located in Veracruz (figure 3), approximately 250 km northeast of Mexico City. The field was discovered in It covers approximately 126 km 2 (7 big areas) and produces an oil of 31 o API. The mature field produces from the Tamabra Reservoir found at a depth of approximately 2,300 meters. The intervals are labeled A through D from bottom to top. The field has been sub-divided into various blocks for management convenience. The distance between existing wells averages about 400 m, which means the average well is located on 40-acre spacing. The rerervoir rock is predominately carbonate and is characterized by permeability values in the range of 0.1 to 25 md based on routine core analysis. More than 100 pressures buildup test suggested that the reservoir permeability ranges from about 5 to 20 md. Porosity appears to average about 10 percent. Connate water varies between rock types, but in general averages 10 to 15 percent. A small gas cap was present in the field at the time of discovery. This indicates the initial reservoir pressure and original bubble point pressure were equal at the gas oil contact. The original reservoir pressure was estimated to be 245 kg/cm 2 and reservoir temperature is approximately 90 o C. The available PVT data, which shows a bubble point pressure of about 245 kg/cm 2, indicates an initial Rsi to be 146 m 3 /m 3, Boi is 1.44 RB/STBO and an initial oil viscosity of 0.81 cp. This low oil viscosity when combined with the injection water viscosity of 0.5 cp and oil/water relative permeability values, leads to a very favorable waterflood mobility ratio of approximately 0.3. It is clearly noted that peak oil production of approximately 150,000 BOPD occurred in 1952 (figure 4), however, after that, the production began to decline. In 1951, and in order to optimize the reservoir management, a waterflooding program was implemented into the peripherical area of the field. Reservoir pressure was maintained and eventually, increased. During the middle of 1970s and 1980s an infill drilling program was initiated to improve sweep efficiency. Significantly, during the last 10 to 15 years, oil production and water production have been relatively constant or slightly increasing. The recent production rates measured at surface conditions is about 12,000 BOPD and MMPCD of gas. Water injection rate is about 32,000 BWPD. Cumulative oil production at the present time is 1,387 MMSTBO. Currently, there are approximately 192 active productors wells. The pumping method was tested in two wells proposed. Both wells were selected to make a comparison between this new pumping system and traditional pump jacks and other conventional systems. The parameters to consider for the evaluation of the technological test were: Maintenance (superficial and subsuperficial equipment) Safety operation Continuous pumping (constant production) Operation efficiency Quiet operation No-visible moving parts Wellsite appearance

4 The results analysis had the main objective to define the production benefit that it s obtained when implementing this new pumping system like an alternative method. The results of the test showed that one well produced continuosly after the installation of the system (figure 5), which indicates that the technology improves the initial conditions of the flow. The second well, after two months of operations was shut down because of mechanical problems. The New System has demonstrated that by using cable and an electronic hydraulic system, it can equal and supersede the production compared with other pumping systems. Making fewer and longer strokes help us to increase efficient and profitability, and decreasing pumping costs. The System is capable of a 184-inch stroke, and can handle 11,000 pounds of peak polished rod load. It is powered by an electrical motor three-phase operation at four strokes per minute. The designed software for the system provides the capability to automatically adjust net pumping speed by changing the delays and the upper and lower stroke limits. The effective cylinder movement speed remains constant. Gas Wells Using This New Pumping System As gas wells age, there is typically an increase in water production. As water production increases, the gas production may decrease. As long as the well has enough bottom-hole pressure, methods such as Plunger Lift may be used to lower hydrostatic pressures and allow gas keeps the well producing. As this bottom hole pressure decreases and Plunger Lift is no longer effective, the need for a lift system to evacuate the water through the tubing to the surface will become necessary. The new method has been designed and tested to fulfill this lifting need. This new pumping method uses special steel cable instead of sucker rods. In place of a pump jack, the System is powered by an electronic hydraulic lifting system. It is controlled and monitored by a central control unit on the well site. Many gas wells that have 2 3 / 8 or 2 7 / 8 tubing for casing need a means of removing water to increase gas production. Current techniques for doing this are pushing wells towards unprofitability. By using special steel cable, water can be pumped to the surface through small tubing allowing gas production to increase. Results showed a gas production increase of between 25 and 50 %. The continuous improvement process will enhance this new pumping system. In addition to the tools that are being used, new tools will be added to the system as it is proven to be a viable economic method. Conclusions The economic life of a marginal well is highly sensitive to the price of oil and cost of production; without improvements to production efficiency, marginal wells often must be shut down or risk operating at a loss. The equipment should be usable on thousands of wells that have been temporarily abandoned. We believe that the method and logic used to evaluate these wells will be of great assistance in increasing production and making these old wells economical again. We believe that this method has as much potential as many other new techniques that have introduced a paradigm shift from the conventional methods to another method of pumping oil wells. Efforts should be concentrating in finding techniques and more efficient systems to recover oil from new, mature and idle wells. In order to have an efficient recovery we need to use engineering and new equipment designs. The solution to this problem is to control the producing parameters, such as pump size, speed, frequency, and stroke length. Controlling the fluid level in the annulus above the pump has turned out to be a very important factor to achieve the desired efficiency of the production and recovery of oil. Pump Rate Discussion Pumping intermittently by placing the unit on a timer is the usual method for reducing pumping frequency in marginal wells. However, there are some disadvantages associated to this method: 1. Intermittent pumping changes the frequency, but not the pumping speed. When the unit comes back on, the loads associated with motion and fluid pound reoccur. 2. During the downtime, liquid flows from the reservoir into the wellbore. This flow builds a liquid level in the casing that creates backpressure on the producing formation. Maximum flow occurs with minimum backpressure; therefore, the liquid column height should be kept as low as possible. 3. Starting the unit from a dead stop requires more power. The start phase also induces a shock on the pumping unit, rods, and pump. 4. If the well produces solids, the downtime allows the solids to settle. These solids may cause the plunger to stick more frequently There is a need for regulating pump rates to deliver the maximum amount of oil to the surface. The objective should be to pump longer strokes and fewer strokes per minute to allow the well to be pumped 24 hours per day with NO shutdown.

5 The new method makes this possible by maintaining a PSI (pounds per square inch) lift pressure that keeps the fluid level in the annulus at a fixed distance above the downhole pump. Solid state electronics are utilized and can be calibrated to sense well functions such as fluid level in the annulus, and to keep fluid level at a constant depth to maximize production and continue to pump 24 hours per day. With this system, the pump jack is replaced with a hydraulic lift system. Using pressure inside the lift cylinder, a continuous measurement of fluid level is achieved. The speed of the pump is then regulated to maximize production. There is NO downtime or need for clocks. Ackowledgments The authors wish to thank Pemex E&P for permission to publish this paper. Special thanks are given to Alfredo Marhx, Marcela Torres and Carlos Gonzalez for their support. References Vann, Roy R.: Reciprocating Pump Standing Head Valve, US Patent No. 6,382,244 B2 (May 7, 2002) Vann, Roy R.: Cable Actuated Downhole Smart Pump, US Patent No. 6,497,281 B2 (Dec. 24, 2002) Vann, Roy R.: Reciprocating Pump Vent-Dump Valve and Methods of Use, US Patent 6,666,270 B2 (Dec. 23, 2003) Vann, Roy R.: Reciprocating Pump Dump Valve and Methods of Use, US Patent 6,672,393 B2 (Jan. 6, 2004) Vann, Roy R.: Method for Using a Reciprocating Pump Vent- Dump Valve, US Patent 6,857,477 B2 (Feb. 22, 2005) Cobb, W. M.: Poza Rica Field: Water Injection Status, Internal Report, March 1, 2006.

6 Figure 1.- The Superficial Computerized Hydraulic Unit. Mature Field Gulf of Mexico Figure 2.- A schematical representation of a flow sheet showing one embodiment of an operating and control apparatus for the pump system of this method. Puebla Veracruz Figure 3.- Mature Oil Field.

7 Primary Production Disperse Injection Frontal Injection Infill Wells Second Period of Injection Qwi 800 Qo, Qw, Qwi (bpd) GOR GOR (m 3 /m 3 ) Qo Qw 0 0 Ene-30 Ene-35 Ene-40 Ene-45 Ene-50 Ene-55 Ene-60 Ene-65 Ene-70 Ene-75 Ene-80 Ene-85 Ene-90 Ene-95 Ene-00 Ene-05 Figure 4.- Production History. PUMP JACK NEW PUMPING SYSTEM Figure 5.- Production during the test in one well.